7272 E. INDIAN SCHOOL ROAD, SUITE 360 

SCOTTSDALE, ARIZONA 85251 

TELEPHONE: 480-505-3900 

FACSIMILE: 480-505-3901 

ERIC L. HISER 

DIRECT LINE: 480-505-3927 

e-mail: ehiser@jordenbischoff.com

LAW OFFICES

JORDEN BISCHOFF

& HISER, P.L.C.

 February 2, 2013 

VIA FEDERAL EXPRESS 

(CONFIDENTIAL BUSINESS INFORMATION REDACTED VERSION)

The Hon. Lisa Jackson 

Administrator 

U.S. Environmental Protection Agency 

USEPA Ariel Rios Building (AR) 

1200 Pennsylvania Avenue N.W. 

Washington, DC 20004 

 Re: Request for Administrative Reconsideration and Stay 

 BART for Units 2 and 3, Apache Generating Station 

 77 Fed. Reg. 72512 (Dec. 5, 2012) 

Dear Ms. Jackson: 

On December 5, 2012, the U.S. Environmental Protection Agency ("EPA”) promulgated 

the final rule “Approval, Disapproval and Promulgation of Air Quality Implementation Plans; 

Arizona; Regional Haze State and Federal Implementation Plans” in the Federal Register at 

volume 77, pages 72512 and following (the “Rule”). As part of the Rule, EPA promulgated a 

Federal Implementation Plan (“FIP”) establishing “best available retrofit technology” or 

“BART” for Apache Generating Station Steam Units 2 and 3 operated by the Arizona Electric 

Power Cooperative, Inc. (“AEPCO”). AEPCO respectfully petitions for administrative 

reconsideration under the Administrative Procedures Act, 5 U.S.C. § 501 et seq. (“APA”), and 

Clean Air Act, 42 U.S.C. § 7401 et seq. (“CAA”), and further requests a stay of the effective and 

compliance dates pending EPA’s action on this petition. The reasons for AEPCO’s petition and 

request for stay are set forth below. 

Background

AEPCO is a rural, consumer-owned generation and transmission electric cooperative 

formed in 1961 to provide electric generation service to local rural, consumer-owned electric 

distribution cooperatives in Arizona. As a not-for-profit cooperative, AEPCO is fully owned by 

its members. AEPCO has six “Class A” members, who participate in and rely on AEPCO’s 

electric generation services, and one “Class D” member that only participates in AEPCO’s 

electric scheduling and trading services. Together, AEPCO’s Class A members serve just under 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 2 

150,000 meters. The electric service base is heavily skewed toward rural residential use, with 

relatively little commercial or industrial load. 

Because of the rural and residential nature of the cooperatives it serves and which 

comprise its membership, AEPCO is a relatively small entity with limited financial means. 

AEPCO operates only one power generation facility: the Apache Generating Station. Apache 

was first constructed with the installation of Steam Unit 1 (“ST1”), a 72 net MW steam unit in 

1963 and Gas Turbine 1 (GT1), a 10 net MW simple cycle gas turbine in 1964. GT1 exhausts 

through either the ST1 windbox and stack or its own stack. In 1978-1979, AEPCO added Steam 

Units 2 and 3 (“ST2” and “ST3”), almost identical Riley Stoker turbocharged boiler units with a 

175 net MW capacity each. ST2 and ST3 are AEPCO’s coal-fired units. A number of other 

simple cycle combustion turbines (GT2 through GT4) were added later. Collectively, Apache 

has approximately 555 MW of net installed capacity. As EPA noted in the Rule, AEPCO and its 

members sold less than 2.5 million MWh of electricity in 2011, well below the 4 million MWh 

or 750 MW net used by the Federal Energy Regulatory Commission (“FERC”) to classify a 

utility as small. 77 Fed. Reg at 72540; 13 C.F.R. § 121.201 n.1. 

AEPCO’s small generating capability results in a correspondingly limited financial base 

and financial resources. AEPCO has patronage capital—essentially earnings contributed by its 

members and legally required to be returned to them in the future—of approximately $103 

million. AEPCO’s total revenues for the last three years ranged from $209 million in 2008 to 

$169 million in 2011. Under the terms of the cooperative’s bylaws, all amounts in excess of 

operating costs, expenses and prior losses are received with the understanding that they are 

furnished by the members as patronage capital and eventually returned back to the members. Att. 

A, AEPCO Bylaws, § 7.02. In addition, AEPCO has approximately $189 million in debt, 

secured by a mortgage with the Rural Utilities Service (“RUS”) and National Rural Utilities 

Cooperative Finance Corporation (“CFC”). The RUS mortgage limits AEPCO’s total debt to 

$600 million, assuming AEPCO can get necessary approval or lien accommodation under RUS 

regulatory and loan processes to fund capital additions. Unlike many other electric cooperatives, 

AEPCO is also subject to regulation by its state public utility commission, the Arizona 

Corporation Commission (“ACC”). The ACC must approve AEPCO’s rates to its Arizona 

members and also AEPCO’s debt arrangements. For the reasons discussed in this petition, 

AEPCO does not believe that it can afford to expand its debt to the extent necessary to 

accommodate the FIP’s imposition of selective catalytic reduction and the SIP’s requirement for 

scrubber upgrades on ST2 and ST3. 

Arizona’s Regional Haze and BART SIP and EPA’s BART FIP

Arizona was a member of the Grand Canyon Visibility Transport Commission and has 

the option of submitting a regional haze SIP pursuant to either 40 C.F.R. §§ 51.308 (a “Section 

308 SIP”) or 51.309 (a “Section 309 SIP”). The Arizona Department of Environmental Quality 

(“ADEQ”) timely submitted a Section 309 SIP on December 23, 2003 and submitted a correction 

adding smoke management rules and updating statutes on December 31, 2004. EPA approved 

the smoke management rules, but did not take any other action on this submittal by ADEQ. 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 3 

On October 13, 2006, EPA revised its rules and required states to submit revised Section 

309 SIP by December 17, 2007. On January 15, 2009, EPA found that Arizona had failed to 

make all or part of required Section 309 SIP submittals. ADEQ subsequently submitted a 

Section 308 SIP on February 28, 2011. This Section 308 SIP submittal was deemed complete by 

operation of law on August 28, 2011. 

On July 20, 2012, EPA published a Federal Register notice of its intent to approve in part 

and disapprove in part the Section 308 SIP and to promulgate a FIP to establish BART 

requirements for three coal-fired utility plants, including AEPCO’s Apache Generating Station. 

AEPCO, the Arizona Utilities Group (“AUG”), and the National Rural Electric Cooperative 

Association (“NRECA”) filed comments, as did ADEQ. AEPCO is a member of both AUG and 

NRECA and adopted their comments in addition to submitting its own comments. 

On December 5, 2012, EPA promulgated its final approval in part and disapproval in part 

of the Arizona Section 308 SIP establishing PM and SO2 BART and promulgated a FIP 

establishing additional NOx BART requirements for AEPCO’s Apache Generating Station. See 

77 Fed. Reg. 72512 (Dec. 5, 2012). EPA’s BART FIP reflected its judgment that low NOx 

burners plus overfire air plus selective catalytic reduction (LNB + OFA + SCR or collectively 

“SCR”) were achievable and cost effective and therefore required as BART. In light of 

AEPCO’s small entity status, EPA did reduce the stringency of the proposed SCR limit from 

0.05 lb/mmBtu 30-day rolling average per unit to 0.07 lb/mmBtu 30-day rolling average over 

both ST2 and ST3. AEPCO’s petition for administrative reconsideration is due within 60 days of 

publication in the Federal Register and is timely submitted. 

AEPCO’s Petition for Administrative Reconsideration and Stay

AEPCO respectfully requests that the Administrator undertake administrative 

reconsideration of the BART FIP pursuant to the APA and CAA. AEPCO specifically requests 

administrative reconsideration of three aspects of the BART FIP: (1) EPA’s determination that 

LNB+OFA+SCR is not “unaffordable” for AEPCO; (2) EPA’s apparent inclusion of the simple 

cycle gas turbine operation of GT1 in the ST1 BART determination; and (3) EPA’s BART limit 

averaging provisions, which may inadvertently preclude restart and proper maintenance of the 

units. The bases for AEPCO’s request are set forth more fully below. 

I. EPA Should Reconsider Its Determination that LNB + OFA + SCR Is “Affordable” 

for AEPCO in Light of the Total Costs of the Regional Haze SIP and FIP. 

In its comments on the draft FIP, AEPCO advised EPA that, based on the best 

information available at that time, the proposed SCR systems on ST2 and ST3 would be 

unaffordable and likely would require that the units be shut down. EPA frankly acknowledged 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 4 

that it did not have the expertise to address this issue.1 Instead, it relied on its contractor, EC/R, 

its subcontractor, Energy Strategies, LLC, and upon a report submitted by EarthJustice’s 

consultant Paul Chernick with Resource Insight. This reliance was and remains misplaced. 

A. EPA’s BART Determination Fundamentally Misunderstands the Relation of 

Cooperative Members to AEPCO. 

1. AEPCO’s Members Are Independent Entities that Make Power and 

Energy Purchase Decisions Based on the Best Interest of Their 

Members 

In its analysis, EPA and its contractor, EC/R, and subcontractor, Energy Strategies, 

assume that AEPCO’s existing membership base will remain with the cooperative. 77 Fed. Reg. 

at 72541 & Table 6. This reflects a fundamental misunderstanding of the relationship of 

AEPCO’s members with AEPCO and with each other. 

Each AEPCO member is a cooperative charged with procuring economical power for its 

members. Because the members are independent legal entities, they have the ability to deal on 

the market for that power. The three smallest members are “all requirements members,” or 

ARMs, who have contracted with AEPCO for all of their power needs. The three large members 

are “partial requirements members,” or PRMs, who have contracted with AEPCO for only some 

of their power needs. The PRMs are free to supplement their AEPCO power supply and/or, 

subject only to contractual minimum provisions, buy market power to substitute for scheduling 

energy from their AEPCO power supply. 

Because AEPCO’s members are independent, they retain the ability to determine whether 

AEPCO’s costs have gone out of line and, if so, to exert pressure through their representatives on 

AEPCO’s board or, in compelling situations, to contract for power elsewhere despite existing 

contractual requirements. This differs from many situations where the rate payers may have the 

theoretical right to contract elsewhere, but do not have the effective ability to do so. In this case, 

AEPCO’s ultimate rate payers are already organized into cooperatives that can contract at 

wholesale to take their business elsewhere should AEPCO’s costs become non-competitive. 

This dynamic is critical to understanding the impact on AEPCO of requiring SCR on Apache 

Station Units ST2 and ST3. 

2. Air Pollution Control Equipment Capital and Operating Costs Are 

Passed on as Fixed and O&M Charges to AEPCO’s Class A Members 

Not Through the Energy Cost 

Rate Schedule A of the Class A Members’ Wholesale Power Contracts or Partial 

Requirements Capacity and Energy Agreements specifies the rates and charges and the 

methodology for developing and administering those rates and charges for capacity and energy 

 

1

 EPA, “Arizona Regional Haze SIP, BART Determination for Apache Generating Station, Supplemental Economic 

Analysis,” at 5 (Nov. 7, 2012). 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 5 

sales made by AEPCO to each of the Class A Members pursuant to their respective contract or 

agreement. See Att. B, Rate Schedule A, page A-1. 

Monthly charges to the Class A Members are calculated and billed in accordance with the 

Wholesale Power Contract or Partial Requirements Capacity and Energy Agreement and consist 

primarily of a Monthly Fixed Charge, Monthly O&M Charge, Base Energy Charge, Base Fuel 

Cost Adjustor Charge, Other Energy Charge, and Other Fuel Cost Adjustor Charge. Att. B, Rate 

Schedule A, page A-3. AEPCO’s expenses and non-tariff revenues are classified by functional 

categories of Fixed Expenses, O&M Expenses and Energy Expenses. Att. B, Exhibit A-2 to 

Rate Schedule A, pages A-2.1 through A-3.3. 

The addition of SCR (or other air pollution control equipment) to ST2 and ST3 would 

result in increased depreciation, taxes, interest and insurance costs. These costs are classified to 

the functional category of Fixed Expenses and result in increased Monthly Fixed Charges to the 

Class A Members. In addition, increased operations and maintenance costs would be classified 

as O&M Expenses resulting in increased Monthly O&M Charges to the Class A Members. 

Therefore, the costs of the SCR (or other air pollution control equipment) would not run through 

the energy rates, but rather through Fixed and O&M Charges. This cost allocation to fixed, not 

per-kWh charges, is a critical fact that is misunderstood in the EPA (and its contractor’s) 

analysis. Att. C, Affidavit of Gary E. Pierson, AEPCO Director of Financial Services, ¶ 4, first 

bullet (hereafter “Pierson Aff.”). 

B. There Are Significant Errors in EPA’s Cost and Affordability Analysis 

In its FIP, EPA states that AEPCO could “spread[] the incremental SCR cost across all 

kWh produced at Apache, both Member Co-ops and off-system or non-Member sales.” 77 Fed. 

Reg. at 72540-41. EPA apparently obtained this incorrect concept from its contractor, EC/R. 77 

Fed. Reg. at 72540-41. In turn, EC/R apparently obtained this information from its 

subcontractor, Energy Strategies, LLC. Energy Strategies, LLC, “Apache Plant: Report on SCR 

Incremental Cost Assessment,” (Nov. 9, 2012, EPA Contract EP-D-10-096, WA 3-04) 

(hereinafter ES Report). This assumption by EPA and its contractor and subcontractor is 

incorrect at multiple levels. Similarly, EPA appears to believe that AEPCO or its member 

cooperatives have existing financial resources that would ameliorate the cost of installing SCR. 

That assumption is also incorrect. 

1. AEPCO Does Not Have the Physical Capacity to Produce Significant 

Excess Energy for Off-System Sales 

AEPCO does not have uncommitted reliable physical capacity in the ST2 and ST3 units 

to produce the quantity of marketable excess energy postulated in the ES Report. In its report, 

Energy Strategies states that AEPCO has the potential to generate 3,037,968 MWh of energy, 

while selling 2,513,087 MWh to its members. ES Report at 5-6. Energy Strategies then assumes 

that “AEPCO may be able to dispose of 524,881 MWh in 2019 by selling that production in to 

the bulk power market.” ES Report at 6. 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 6 

Energy Strategies apparently derives its postulated 3,037,968 MWh of energy by 

multiplying AEPCO’s “capacity factor” of 0.85 by the full nameplate capacity of ST2 and ST3 

of 204 MW each. If correct, this would give the nominal “potential” generation of 3,037,968 

MWh. It is not correct. 

AEPCO’s correct net generating capacity is only 175 MW per unit due to auxiliary loads 

at Apache and power reserve requirements. See Att. D, AEPCO Energy Information 

Administration (EIA) Form 890 Report, at 2-3. In other words, Energy Strategies overstates the 

ST2 and ST3 capacity by 16.7%. As discussed later, the SCR would reduce the coal generating 

capacity by another 1.2 MW. Using the correct net generating capacity, AEPCO only has a 

“best-case” realistic potential of 2,606,100 MWh at 0.85 capacity factor—more than 430,000 

MWh less than the sales potential Energy Strategies asserted in its report. AEPCO’s actual 

generation figures from ST2 and ST3 since 2004 are included in Attachment E, AEPCO’s 

Generator Summary Reports from 2004 to 2011. See also Att. F, Declaration of Richard E. 

Stinneford, Managing Member, Washington Utilities Group, LLC, ¶ 5.c. (hereafter “Stinneford 

Decl.”). 

2. AEPCO Does Not Have the Contractual Authority to Sell Significant 

Excess Energy on Its Own Account. 

In addition to assuming that AEPCO has spare energy available from ST2 and ST3, 

which it does not have, Energy Strategies also criticized AEPCO’s cost analysis because “the 

analysis should account for a share of the SCR cost going to the off-system sale volumes and not 

only allocated to member rates.” ES Report at 6. This assertion is incorrect and reflects two 

fundamental misunderstandings of how AEPCO serves its members. 

First, as discussed in Section I.A.2 above, the AEPCO Class A Member wholesale power 

contracts specify that fixed charges (i.e., such as the increased depreciation, taxes, interest, 

insurance, etc. associated with SCR) are recovered in the monthly fixed charge rates of the Class 

A Members and not through the energy rate. See Att. B, Rate Schedule A and Exhibits A-2, A-3 

and A-4 of Rate Schedule A. Therefore, all SCR financing costs must be directly charged to the 

Class A Members and their rural customers regardless of whether AEPCO can or does make 

sales of surplus energy. Att. C, Pierson Aff. ¶ 4, second bullet. 

Second, AEPCO’s three Partial Requirement Members (PRMs) control XXX% of ST2 

and ST3 capacity. Att. B, Rate Schedule A, Appendix A to Exhibit A-5. The PRMs schedule 

that capacity, not AEPCO. As a result, even though the PRMs are not specifically dedicated 

control and operation of their allocated capacity portion of ST2 and ST3, AEPCO’s obligation to 

meet their hourly schedules and potential schedule changes precludes AEPCO from committing 

to sell from the PRMs interest in AEPCO units more than on a spot market basis. Att. G, 

Affidavit of Richard P. Kurtz, AEPCO Vice President of Power Resources and Planning, ¶ 4, 

first bullet (hereafter “Kurtz Aff.”). Additionally, if the PRMs’ energy costs from their interest 

in AEPCO units are less than the energy cost that can be obtained on the economy market, then 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 7 

the PRMs will make the off-system sales, not AEPCO, and the benefits would flow to them 

through the Purchase Power and Fuel Adjustment Clause (“PPFAC”) and, eventually, the energy 

rates. Att. B, Exhibit A-4 to Rate Schedule A, page A4-17. If the PRMs are not “in the money,” 

AEPCO would not be in the money either and sales will not be made because they would be 

made at a loss to AEPCO and its members. Att. H, Affidavit of Walter T. Bray, AEPCO 

Director of Energy Services, ¶ 4, first bullet (hereafter “Bray Aff.”). 

AEPCO does control the scheduling for its All Requirements Members (ARMS), which 

accounts for the remaining XX% of AEPCO’s capacity. However, as with the PRMs, although 

AEPCO does the scheduling, any sales are for the benefit of AEPCO’s members and revenues 

are shared among the ARMs on a contract basis. As with the PRMs, if the ARMs cannot make 

money on a sale, AEPCO cannot make money either. Att. G, Kurtz Aff. ¶ 4, second bullet. 

In short, all of AEPCO’s generation capacity is dedicated to the Class A Members. It is 

not, as Energy Strategies wrongly asserts, available for AEPCO to contract for or profit from as 

an off-system sale. See Att. B, Appendix B to Exhibit A-5 to Rate Schedule A; Att. G, Kurtz Aff. 

¶ 4, third bullet. 

Because (1) AEPCO does not have the energy capacity that the ES Report assumes; (2) 

AEPCO’s members benefit from any margins on off-system sales; and (3) in any event, all SCR 

costs would be recovered through fixed monthly charges to AEPCO’s Class A Members, not 

energy sales proceeds, the ES Report grossly underestimates the costs and overestimates the 

potential for recovery of the costs imposed by the FIP SCR requirement on AEPCO and its 

members. 

3. Apache Station’s Age and Heat Rate Weighs Against Surplus Energy 

Sales 

 

AEPCO’s Apache Station ST2 and ST3 units are over 30 years old. As a result of their 

age, ST2 and ST3 have a relatively high “heat rate.” A high heat rate means that their relative 

energy cost is high compared to the market. The current net heat rates of AEPCO’s ST2 and 

ST3 are: 

Table 1. AEPCO Net Heat Rates, Btu/kWh 

Unit Full Load Net Heat Rate Avg. Net Heat Rate (3 yr, 62%) 

ST2 XXXX XXXX 

ST3 XXXX XXXX 

Combined ST2/ST3 XXXX XXXX 

The approximate average heat rate of a newer combined cycle unit would, for comparison 

purposes, be in the range of 7,000 to 7,800 Btu/kWh at the approximate elevation of Phoenix, 

Arizona. Att. I, Affidavit of Barry A. Brown, AEPCO Director of Engineering, ¶ 4, first bullet 

(hereafter “Brown Aff.”). 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 8 

Because of the relatively high heat rate of AEPCO units ST2 and ST3, the economy 

market price needs to become relatively high before AEPCO or its members can make margins 

over ST2 or ST3 energy costs for sale into the market. And, as discussed under #2 above, the 

revenues from such sales go to AEPCO’s members, not to AEPCO. Att. H, Bray Aff. ¶ 4, 

second bullet. 

4. EPA’s BART Determination May Have Been Influenced by an 

Erroneous Understanding of AEPCO’s Earnings Position and 

Internal Financing Capacity 

EPA cites the Chernick Report in the preamble to the FIP for the proposition that AEPCO 

has capital resources, operating margin and a coal contract recovery to finance the bulk of the 

cost of the SCR system. 77 Fed. Reg. at 72539. To its credit, EPA noted that “[w]hile some of 

these funds may be available for capital expenditures such as pollution controls, we have 

assumed for the purpose of our analysis that financing will be necessary to achieve the pollution 

reductions required by our action.” 77 Fed. Reg. at 72540. AEPCO agrees with EPA’s 

conclusion and wishes to emphasize why financing will be required. 

First, as noted elsewhere, AEPCO does not have “capital” in the traditional sense of an 

investor owned utility. Instead, AEPCO has “patronage capital,” which is retained earnings not 

yet returned to its members. Only the patronage capital necessary to maintain financial stability 

is retained at the generation cooperative. Any excess is required to be returned to the members. 

Att. J, Affidavit of Peter F. Scott, AEPCO Chief Financial Officer, ¶ 4, first bullet (hereafter 

“Scott Aff.”); Att. A, AEPCO Bylaws, § 7.02. 

AEPCO does not have any ability to issue equity instruments and generally does not have 

the ability to seek capital contributions from its members for capital expenditures. All 

expenditures for plant improvements or retrofits such as SCR are financed by debt instruments 

secured by the RUS mortgage. In short, AEPCO does not have the ability internally to raise 

capital. Att. J, Scott Aff. ¶ 4, second bullet. 

Second, AEPCO’s operating margins generally are fairly thin and net cash flows have 

been historically flat and frequently negative. This net cash effect can be seen even during the 

years of relatively strong net margins referenced in the Chernick report. Routinely, principal 

payments and non-operating expenditures result in little remaining cash margin. The margins 

generated by AEPCO’s present (or pending) rates are not adequate to cover either the fixed costs 

or the O&M costs that would likely be incurred by implementation of SCR systems. As noted in 

AEPCO’s comments, operating margins have been less than or little more than the amount 

needed to finance the increase in debt service. Because capital construction costs are front 

loaded, AEPCO does not have the internal ability to finance the construction of the SCR 

systems. It must have a loan, which must be secured by the RUS mortgage and AEPCO must 

meet RUS’s TIER and DSC covenant requirements. These mortgage covenants cannot be 

achieved with the margins provided by AEPCO’s present (or pending) rate structure if SCR 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 9 

systems are implemented. Significant rate increases would be required. Att. J, Scott Aff. ¶ 4, 

third bullet. 

Third, it is true that on November 22, 2011, AEPCO received a favorable ruling from the 

Surface Transportation Board (“STB”), which awarded AEPCO prescribed rail rates for a ten 

year period from the date of the filing, December 30, 2008. $9.2 million of reparations were 

paid retrospectively to reimburse AEPCO for amounts of unreasonably high rail rates charged by 

the railroads during the pendency of the STB case (2009-2011). The STB estimated that 

AEPCO’s future rail rates would be reduced by $53.8 million over the remaining seven year life 

of the rate prescription, the period of 2012-2018. The STB projected the savings based on 

AEPCO’s based on 2009 shipments, but AEPCO’s shipments starting in 2011 have been at a 

substantially lower level. In addition, the effect of the estimated $53.8 million of future relief is 

already included in the anticipated rates used in AEPCO’s financial forecast and cannot be 

counted twice to reduce members’ rates. AEPCO has a PPFAC through which under- or overcollection through rates of fuel costs are passed on to purchasers of its power, either as a charge 

or refund respectively. Through this process, no funds are generated that can be used to offset 

the cost of pollution control equipment. As rail rates are a part of the fuel expense that flows 

through the PPFAC, the reduced rail rates ordered by the STB will be refunded through the 

PPFAC mechanism and will not increase cash at AEPCO. Att. C, Pierson Aff. ¶4, third bullet. 

Of the reparations amount of $9.2 million, approximately $XX million will be refunded 

according to contract provisions to parties that AEPCO had long term power sales agreements 

with during that time period (since expired). The remaining $XX million of reparations will be 

refunded back to its members through the PPFAC mechanism. The reparations have not been 

flowed through the PPFAC pending the outcome of appeals of the STB decision and order. Att. 

C, Pierson Aff. ¶ 4, fourth bullet. 

C. Installation of LNB + OFA + SCR, Added to Other BART Costs, Is 

Unaffordable Because It Renders ST2 and ST3 Non-Viable 

Congress, in establishing the BART requirement, included consideration of cost and the 

remaining economic life of the unit. 42 U.S.C. § 7491(b). Congress also provided that greater 

flexibility should be provided for the review of “small” electric generating powerplant of less 

than 750 MW. 42 U.S.C. § 7491(b)(2). Clearly, AEPCO is such a “small” generating plant 

entitled to greater latitude in the BART determination. 

EPA has recognized that “[e]ven if the [proposed BART] control technology is cost 

effective, there may be cases where the installation of controls would affect the viability of plant 

operations.” 40 C.F.R. Part 51, App. Y, § IV.E.3(1). EPA specifically noted that “effects on 

product prices, the market share, and profitability of the source” should be considered in 

determining whether a proposed BART is appropriate. Id. § IV.E.3(2). Apache Station’s 

ongoing viability is clearly at stake should SCR plus scrubber upgrades be imposed on ST2 and 

ST3. 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 10 

1. The Costs of Installation of LNB + OFA + SCR Are Approximately 

$192 Million 

As described in AEPCO’s initial comments, its response to EPA’s information request, 

and its final comments, the total cost of SCR installation is estimated at approximately $192 

million. AEPCO recognizes that EPA disagrees as to whether all of these costs are appropriately 

considered in determining the cost of control. AEPCO is not, however, contending that its costs 

of control on a $/ton of pollutant basis are substantially out-of-line with those for some other 

utilities. Instead, AEPCO’s contention is that the overall cost of the BART determination for 

Apache Station is unaffordable and will affect the viability of Apache Station operation. 

Because plant viability is a different question than cost effectiveness,2

 AEPCO believes that a 

correct analysis requires consideration of costs which might be excluded in the cost effectiveness 

analysis. 

In Attachment K, AEPCO has itemized the additional costs that EPA excluded from 

AEPCO’s cost analysis in the preamble to the final Rule. AEPCO has documented why each of 

those costs are expenses that will actually be incurred and thus burden AEPCO’s future 

operations. Att. C, Pierson Aff. ¶ 4, fifth bullet. Accordingly, EPA should give consideration to 

the full $192 million cost of LNB + OFA + SCR installation for purposes of evaluating the 

impact on plant viability. 

If EPA disagrees, perhaps taking the position that some or all of these costs will not be 

actually incurred by AEPCO, EPA must provide a reasoned basis for that position, explaining 

why these costs would not be incurred or would not be included in AEPCO’s financing cost and 

the corresponding cost charged to its members and their ratepayers. The mere fact that these 

costs may not be known with certainty is not a basis for categorically excluding them; they are 

still real costs that must be accounted for in construction and which will be borne by AEPCO, its 

members and their retail members. Att. C, Pierson Aff. ¶ 4, sixth bullet. 

2. The Cost of Installation of SO2 Scrubber Upgrades Mandated by 

BART Is an Additional $14 million, Bringing the Total Cost of BART 

for Units ST2 and ST3 to $206 Million 

In addition to the LNB + OFA + SCR cost, AEPCO is also required to install certain 

scrubber upgrades by the SIP-approved BART. See ADEQ, Section 308 SIP, App. D, Table 1.3; 

40 C.F.R. § 52.145(e)(1). The cost of these units is estimated at $14 million. Attachment L sets 

forth an engineering overview of the costs of installation. The total cost of BART for ST2 and 

ST3 is thus expected to be approximately $206 million. 

The full BART cost of $206 million is the appropriate benchmark against which to assess 

affordability. Some additional controls on ST1 are also required, but these affect the cost of that 

 

2 Compare Guidelines § IV.D.4(4) & (5) (referring to EPA’s Control Cost Manual as determining which costs are to 

be considered) with § IV.E.3 (broad consideration of “where the installation of controls would affect the viability of 

continued plant operations” and recommending an “economic analysis”). 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 11 

unit, not ST2 or ST3, and hence do not have the same direct economic impacts as the SCR 

installation on units ST2 and ST3. AEPCO is thus concentrating its analysis on the impact of 

these costs on the future use and viability of Units ST2 and ST3. 

3. The Annualized Fixed Financing Cost to AEPCO of the LNB + OFA + 

SCR and SO2 Scrubber Upgrades Is Approximately $21.5 Million per 

Year 

Applying annualized assumptions, as set forth in Attachment M, the additional fixed 

charges of adding the SCR system and the upgraded scrubbers to ST2 and ST3 is approximately 

$21.5 million per year. These costs will be added to AEPCO’s existing fixed charges for these 

units. The following table summarizes the impact on AEPCO’s fixed charges: 

Table 2. Fixed Cost Impacts of SCR + Scrubber Upgrades 

Category AEPCO Comments (projected 2020) 

Annualized Existing Fixed 

Charges 

$ XXXXXX 

Annualized Fixed Charges 

Increase for ST2 & ST3 

SCR + scrubber upgrades 

$ 21,537,000 

Total Annualized Fixed Charges: $ XXXXXX XXX% increase in annual 

fixed charges 

Net KW-Months XXXXX Forecast demand in 2020 

Fixed Charges, $/KW-Month $ XXX $/KW-Month, XX% increase 

In the last two lines of Table 2, AEPCO has converted the increase in annual fixed charges to its 

corresponding cost in $/KW-Month, which is the unit of measurement typically used to purchase 

or sell long term or “firm” electrical capacity. Based on AEPCO’s projected power sales from 

existing system resources to its members, AEPCO will have a total fixed charge cost expressed 

on a $/KW-Month of approximately $XXX. Converting fixed charges to $/KW-Month allows a 

better understanding of the impact of the increase in fixed costs on AEPCO’s cost structure and 

competitive position. 

 

4. The O&M Cost to AEPCO of the LNB + OFA + SCR and SO2

Scrubber System is $10.7 Million Per Year. 

In addition to the financing costs, installation of the SCR and scrubber upgrades will 

impose additional Operations and Maintenance (O&M) costs on AEPCO. These costs were 

estimated at $ 10.7 million annually (in 2020 dollars) for the SCR and scrubber upgrades. The 

details for these cost analyses are set forth in Attachment K (LNB + OFA + SCR) and 

Attachment L (scrubber upgrades). As noted above, O&M represents part of the Monthly O&M 

Charge that AEPCO charges its members. The following table summarizes the impact on 

AEPCO’s O&M expense. 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 12 

Table 3. O&M Impacts of SCR + Scrubber Upgrades 

Category AEPCO Comments (projected 2020) 

Annualized Existing O&M $ XXXXXX 

Annualized O&M Increase for 

SCR and scrubber upgrades 

$ 10,763,000 

Annualized Total O&M $ XXXXXX XX% increase 

Total O&M Charges, $/KWMonth $ XXX 

In the last two lines of Table 3, AEPCO has converted the increase in monthly O&M charges to 

its corresponding cost in $/KW-Month, which is the unit of measurement typically used to 

purchase and sell long term capacity. Based on AEPCO’s projected power sales from existing 

resources to its members, AEPCO will have a total O&M charge cost per KW-Month of 

approximately $XXX. Converting O&M charges to $/KW-Month allows a better understanding 

of the impact of the increase in O&M costs on AEPCO’s cost structure and competitive position. 

5. The Combined Effect of Fixed Costs and O&M Costs on AEPCO’s 

Effective $/KW-Month Capacity Cost Is Material 

Adding the SCR and scrubber upgrade-related fixed charges and O&M charges to the 

existing fixed and O&M charges gives AEPCO’s “new” capacity cost in $/KW-Month. That 

cost is estimated as follows: 

Table 4. Capacity Cost with SCR + Scrubber Upgrades 

Category AEPCO 

(projected 2020) 

Existing Fixed Charges 

$/KW-Month 

$ XXX 

Existing O&M $ XXXX 

Total Existing Fixed and O&M 

Charges, $/KW-Month (Capacity 

Charge) 

$ XXXX 

 

Additional Fixed Charges for 

SCR + Scrubber Upgrades 

$/KW-Month 

$ 5.00 

Additional Fixed O&M Costs for 

SCR + Scrubber Upgrades 

$/KW-Month 

$ 2.50 

Total Additional Fixed & O&M 

Costs for SCR + Scrubber 

Upgrades, $/KW-Month 

$ 7.50 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 13 

Category AEPCO 

(projected 2020) 

Post-BART Capacity Charge 

$/KW-Month 

$ XXX 

AEPCO’s capacity charges, expressed in a $/KW-Month basis, will increase by XXX% 

to recover the SCR and scrubber upgrade related cost for ST2/ST3 based on projected member 

demand of XXXXX KW-Months in 2020. Class A Members’ loads and consequent sales of 

energy from AEPCO resources are not forecast to grow significantly in the next ten years. Using 

the fixed and O&M costs discussed above translates to additional charges to AEPCO’s Class A 

members as follows: 

Table 5. Impact of Costs on AEPCO Class A Members 

AEPCO Member Group Percent Capacity Cost Impact 

Collective All Requirements Members 

(Anza, Duncan, Graham Electric Cooperatives)

XX XXXXXXX 

Mohave Electric Cooperative XX XXXXXXX 

Sulphur Springs Valley Electric Cooperative XX XXXXXXX 

Trico Electric Cooperative XX XXXXXXX 

Att. C, Pierson Aff. ¶ 4, seventh bullet. 

AEPCO’s members must pay these fixed charges whether they purchase any electricity

from AEPCO or not. It is also important to realize that AEPCO’s members must act on this 

information quickly given the time lag associated with AEPCO’s options including, but limited 

to purchasing power, installing air pollution controls, or building new assets should alternate 

courses of action be deemed necessary or prudent by AEPCO or its members. Att. J, Scott Aff. ¶ 

4, fourth bullet. 

6. Apache Station Units ST2 and ST3 Operate in a Competitive Market 

As a result of area-wide changes in wholesale and retail electric supply, there is now a 

very competitive marketplace for the sale of capacity and energy. Not only AEPCO can 

participate in these markets, but also AEPCO’s Class A members could as well. The existence 

of competitive markets means that ST2 and ST3 must be situated to compete in those markets 

with reliable, reasonably-priced energy to retain AEPCO’s members. Att. H, Bray Aff. ¶ 4, third 

bullet. 

Determining the “market rate” for capacity is a constantly changing and dynamic 

exercise. While AEPCO obviously knows its own $/KW-Month capacity rate, it does not know 

what that rate is or will be for its competitors. Instead, AEPCO and its members must proceed 

by analysis and informed judgment.
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 14 

In this case, AEPCO can draw some conclusions from two recent developments: the 

Southwest Public Power Resources (“SPPR”) Group Purchase Power Agreement (“PPA”) with 

Sempra Generation, and Salt River Project’s (“SRP’s”) recent purchase of one block of the 

Mesquite Generating Station from Sempra Generation. 

 The SPPR PPA, involves 21 public entities: 

o The PPA is based on a capacity fixed cost of $XXX KW-Month plus a fixed 

O&M charge, presently estimated at $XXX KW-Month, for a total fixed cost of 

approximately $XXX KW-Month in 2015. The $XXX is fixed, but the $XXX 

escalated at 3% annually would be $XXX in 2020 and the total fixed would then 

be $XXXX. Att. G, Kurtz Aff. ¶ 4, fourth bullet. 

o The PPA energy cost is based on natural gas at the So-Cal Border daily index as a 

fuel cost, applied to a heat rate of XX MMBtu/MWh, increased by a sales tax of 

5%, plus a variable O&M charge starting at about $XXX per MWh in 2015. 

Escalating the $XXX by 2.5% annually would be $XXX in 2020. Att. G, Kurtz 

Aff. ¶ 4, fifth bullet. 

 SRP recently purchased one block of the Mesquite merchant power plant for $371 

million. Mesquite is a dual 624 MW natural gas combined-cycle plant. 

o Using standard assumptions for financing costs, the capacity costs would be 

$7.50-8.50/KW-Month, lower than the SPPR PPA. AEPCO assumes that the 

fixed and variable O&M costs are the same as stated in the SPPR PPA, as those 

are based on the same Sempra Generation plant. Att. C, Pierson Aff. ¶ 4, eighth 

bullet. 

o Finally, we assume that the energy cost would be essentially the same formulation 

as in the SPPR PPA, but based on the actual heat rate (estimated 7000 

mmBtu/kWh) and the actual cost to SRP of the natural gas. Att. G, Kurtz Aff. ¶ 

4, sixth bullet. 

By comparison, AEPCO ST2 and ST3 operate with a best case heat rate in the XXXXXXX 

MBtu/kWh range at the present time and, due to age, significant improvement in those heat rates 

would not be anticipated. AEPCO has calculated its average actual net heat rate for ST2 and 

ST3 over the last three years at XXX MBtu/kWh based on an average capacity factor of XX%. 

Att. I, Brown Aff. ¶ 4, second bullet. 

Valley Electric Association obtained a forward power estimate from ACES Power 

marketing to assist in the long-term valuation of the Sempra PPA discussed above. Critically, 

the ACES analysis discussed two issues: Forward Power Demand, priced in $/MWh, and Market 

Implied Heat Rate (MBtu/kWh). This forecast shows on-peak power demand increases from 

$XXXX/MWh in the 2017-2018 period to perhaps as high as $XXXX/MWh in 2028. However, 

it also shows that the market implied heat rate will decline from a present XXX MBtu/MWh in 

2018 to approximately XXX MBtu/MWh to approximately 2020. Att. G, Kurtz Aff. ¶ 4, seventh 

bullet. 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 15 

 AEPCO also obtained another forward power estimate from ACES that projects the likely 

range of the market implied heat rate from 2013 to 2018, which AEPCO has extrapolated to 

2020. Essentially, this is the heat rate that ST2 and ST3 must meet to be in the money going 

forward. Based on the mean market implied heat rate, AEPCO ST2 and ST3 would be in the 

money only two months of each year from 2013 to 2017 and three months from 2018 through 

2020 on an energy basis only. 

7. Apache ST2 and ST3 Are Non-Viable with SCR + Scrubber Upgrade 

Costs Added 

AEPCO believes that ST2 and ST3 are non-viable with the added costs of SCR and 

scrubber upgrades. First, and less importantly, SCR imposes an additional energy cost because it 

reduces the capacity output of ST2 and ST3 by 1.2 MW for the same coal input. With this 

adjustment, AEPCO’s full load heat rates are as follows: 

Table 6. AEPCO’s Post-SCR and Scrubber Upgrade Heat Rate 

Units Firing Adjusted Full Load Net Heat Rate 

AEPCO on ST2 and ST3 on coal XXXX Btu/kWh 

AEPCO on coal w/SCR XXXX Btu/kWh 

AEPCO on gas XXXX Btu/kWh 

Att. I, Brown Aff. ¶ 4, third bullet. In addition, the heat rate, and the associated energy cost 

($/MWh), will be higher if ST2 and ST3 operate at less than full output. In contrast, a modern 

combined cycle gas turbine may have heat rates in the 7,000 to 7,800 Btu/kWh range in much of 

Arizona. Att. H, Bray Aff. ¶ 4, fourth bullet. Any deterioration in the heat rate, and the 

corresponding increase in energy cost, will cause overall cost to increase on a $/MWh basis.

The result of this cost differential is that there will be few times, except at peak energy 

demand, when ST2 and ST3 will be cost effective on an energy cost basis. Thus, AEPCO’s 

members will not “buy” energy from ST2 or ST3, but rather will purchase “against” ST2 or ST3 

and buy their power from outside sources. As a result, utilization of ST2 and ST3 will fall to the 

minimum contract levels of XXX MW combined. Att. H, Bray Aff. ¶ 4, fifth bullet. However, 

the Wholesale Power Contract between AEPCO and its Members provide for waiver of the 

contract minimum if the Member’s actual hour’ s load is lower than its Allocated Capacity 

Percentage (ACP) of available capacity of ST2 and ST3. It is thus not certain that even the 

contract minimum of XXX MW combined will be maintained at all times. Att. G, Kurtz Aff. ¶ 

4, eighth bullet. Below contract minimum, ongoing operation of a unit becomes less reliable due 

to operational constraints. Att. I, Brown Aff. ¶ 4, fourth bullet. 

Second, and more importantly, when fixed costs are added, the implications of the market 

trends discussed in section I.C.6 above for AEPCO if SCR is required to be added to ST2 and 

ST3 are grave, as can be seen in the following analysis: 

Table 7. Annualized Market Impact on AEPCO of SCR + Scrubber Upgrades 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 16 

Market Price Forecast (ACES) Peak Rate Wrap Rate Comments 

High Price, $/MWh Based on market 

Low Price, $/MWh 

AEPCO/PPA Cost Comparison PPA AEPCO Comments 

Fixed Charge, $/KW-Month 

O&M Charge, $/KW-Month 

Capacity Charge, $/KW-Month Capacity = Fixed + O&M 

Capacity Charge, $/MWh Based on forecast energy 

usage 

Variable O&M Charge, $/MWh PPA is SPPR escalated at 

XXX% 

Energy Charge, $/MWh Assumes gas at $XX and 

coal at $XX ($/MMBtu). 3 

Total Cost, $/MWh 

The Table 7 analysis shows: 

 That AEPCO will operate with a premium over market of approximately $XXXX/MWh 

versus a long term PPA’s equivalent total cost XXXXXXXXXXXXXXXXXXX. 

 That AEPCO will operate with a cost structure in excess of its likely recovery in either 

Peak or Wrap rates in 2020. On a peak basis, AEPCO’s deficit ranges from -XXXX to -

$XXXXX/MWh. On a wrap basis, AEPCO’s deficit ranges from -XXXX to -

$XXXXX/MWh. 

 Energy charges are more variable and difficult to forecast, but if natural gas remains 

cheap, then AEPCO’s energy cost advantage (coal over natural gas) will decline, 

rendering AEPCO’s energy charges less competitive. As forecast, AEPCO is very 

concerned that its energy charges may only be competitive in 2 to 3 months a year. 

 As forecast, AEPCO is wholly non-competitive on a long-term capacity basis. Its ability 

to compete on the spot market is also impaired. 

Att. H, Bray Aff. ¶ 4, sixth bullet (Table 7 is erroneously called out as Table 6 in this Affidavit). 

This premium over the market and competitive PPAs is unsustainable. Att. G, Kurtz Aff. 

¶ 4, ninth bullet. As it applies to AEPCO’s PRMs, the difference in cost of staying in AEPCO 

versus leaving AEPCO and buying power on the open market becomes quite large. Here is the 

breakdown: 

 

 

3

 If gas is cheaper, that adverse effect on AEPCO becomes greater. 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 17 

Table 8. AEPCO Premium Over Market

AEPCO Member Group Annual Premium 

Collective All Requirements Members 

(Anza, Duncan, Graham Electric Cooperatives) 

Mohave Electric Cooperative 

Sulphur Springs Valley Electric Cooperative 

Trico Electric Cooperative 

While it is true that there are contractual impediments to a PRM (or ARM) leaving AEPCO, 

member cooperative boards have legal duties to their members. As stated in the affidavits of the 

chief executive officers of Mohave Electric Cooperative, Sulphur Springs Valley Electric 

Cooperative and Trico Electric Cooperative (AEPCO’s PRMs), the capacity premium and energy 

charges resulting from SCR + scrubber upgrades, if incurred as presently promulgated, will 

result in each PRM minimizing purchases of AEPCO power and reviewing all available options 

to reduce exposure to AEPCO costs—including potentially withdrawing from AEPCO. See Att. 

P, Affidavit of J. Tyler Carlson, Chief Executive Officer, Mohave Electric Cooperative, Inc., ¶¶ 

6, 8; Att. Q, Affidavit of Creden W. Huber, Chief Executive Officer, Sulphur Springs Valley 

Electric Cooperative, Inc., ¶¶ 6, 8; Att. R, Affidavit of Vincent Nitido, Chief Executive 

Officer/General Manager, Trico Electric Cooperative, ¶¶ 6-8 . If even one PRM leaves and 

shifts their costs to the remaining members, the premium upon the remaining members would 

increase by 45% to 79%. What would likely happen is that AEPCO would dissolve, leaving all 

of the Apache Station Units potentially as stranded assets. Given the heat rate and other 

penalties discussed above, it is not clear that a purchaser could be found for the assets, 

particularly if encumbered by the LNB + OFA + SCR and scrubber upgrade requirements. Att. 

G, Kurtz Aff. ¶ 4, tenth bullet; see also Att. F, Stinneford Decl. ¶ 5.f. 

 AEPCO retained Richard E. Stinneford, Managing Member of the Washington Utility 

Group, LLC (“WUG”), to provide a third party review of AEPCO’s financial projections and 

discussion above in this petition for administrative reconsideration. AEPCO commissioned this 

review by WUG to provide assurance to EPA that the projections included in this petition are 

based upon real circumstances and concerns. Based upon his over 30 years of experience, Mr. 

Stinneford concluded: 

 The financial assumptions and rate forecasts generated by AEPCO are appropriate. Att. 

F, Stinneford Decl. ¶ 5.a. 

 AEPCO’s assumptions with respect to the potential output of the [Apache Generating 

Station] are correct and those of Energy Strategies are incorrect. Att. F, Stinneford Decl. 

¶ 5.c. 

 AEPCO’s and its members’ ability to off-load any incremental costs associated with the 

SCR + scrubber system is “extremely limited.” Att. F, Stinneford Decl. ¶ 5d. 

 Costs increases resulting from the EPA’s ruling will drive AEPCO’s wholesale rates 

further above regional market rates. Att. F, Stinneford Decl. ¶ 5.e. 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 18 

 Should increases in wholesale rates lead to the default or withdrawal of an AEPCO 

member, it draws into question the continued viability of AEPCO. Att. F, Stinneford 

Decl. ¶ 5.f. 

Mr. Stinneford’s declarations provide assurance that AEPCO’s concerns are well-founded and 

not speculative. AEPCO’s members are very concerned, as expressed in the affidavits of their 

chief executive officers discussed above and included in Attachments P, Q and R to this petition. 

II. EPA Should Reconsider Including GT1 in the ST1 BART Determination 

Upon reviewing the BART determination formalized by EPA’s SIP approval in part and 

disapproval in part and FIP, AEPCO developed a question about how to account for emissions 

from Gas Turbine #1 (GT1) when they are ducted through ST1. GT1 is a simple cycle 

combustion turbine located adjacent to ST1 that can have its exhaust either routed through its 

own stack or introduced into the windbox of ST1, where it adds heat to the ST1 boiler windbox, 

in which case the exhaust exits through the ST1 stack. 

In its BART submittal to ADEQ, AEPCO listed units ST1, ST2 and ST3 as potentially 

BART-eligible. See “BART Analysis for Apache Generating Station, Steam Unit 1,” CH2MHill 

(Dec. 2007) [Hereinafter CH2MHill Report]. The CH2MHill described ST1 as follows: 

ST1 is a wall-fired steam electric generating unit that can burn pipeline natural 

gas (PNG) and No. 2 through No. 6 fuel oils. The unit typically produces up to 71 

MW, but is permitted to produce up to a maximum capacity of 85 MW. Currently, 

there is no emissions control equipment installed on ST1. 

ST1 is located adjacent to Gas Turbine #1 (GT1) at Apache Generating Station. 

These two units can be operated separately or in a combined cycle configuration. 

Typical practice is to operate these units together, and under this case GT1 

exhaust is routed through the ST1 boiler. Although GT1 emissions can contribute 

to total emissions from the ST1 stack when the units are operated in a combined 

cycle configuration, only ST1 is BART eligible. Therefore, ST1 is considered a 

stand-alone unit for this BART analysis. 

CH2MHill Report at 2-1. In the BART technical demonstration, CH2MHill recommended that 

Low NOx Burners (LNB) plus Flue Gas Recirculation (FGR) be used. It was recommended that 

the FGR be obtained from the existing GT1 exhaust. CH2MHill Report at 3-7 & 5-36. 

CH2MHill also noted that FGR could come from other sources, as well as GT1. It is apparent 

that AEPCO and its contractor, CH2MHill, did not propose to extend BART to GT1 beyond the 

narrow context of when it is providing FGR to support the ST1 BART recommendation. 

ADEQ, in its BART SIP, determined that “for Unit 1, BART for NOx is the installation 

of LNB with FGR (from GT1) with a NOx emissions limit of 0.056 lb/MMBtu when burning 

pipeline quality natural gas (PNG).” ADEQ, Technical Support Document for Arizona BART 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 19 

Analyses and Determinations, page 54 of 115 [hereinafter ADEQ TSD]. Significantly, ADEQ 

stated that “Apache Steam Unit 1 is a wall-fired steam electric generating unit that can burn 

natural gas and numbers 2 through 6 fuel oils.... The remaining four units at the Apache 

Generating Station are simple cycle gas turbines. Steam Unit 1 and Gas Turbine 1 can be 

operated separately or in a combined cycle configuration.” ADEQ TSD, at 49 of 115. From this 

description, it is apparent that ADEQ also treated the relevant unit as ST1, including GT1 only to 

the extent that it is providing FGR to ST1 in “combined cycle” operation. 

In the intervening period, AEPCO discussed the status of ST1 and GT1 combined 

operations, which AEPCO had listed as “combined cycle,” with EPA Clean Air Marketing 

Division (“CAMD”). Based upon CAMD’s review, AEPCO was advised to reclassify the 

ST1/GT1 combined operation from “combined cycle” to “wall-fired boiler.” A copy of that 

correspondence is included in Attachment N. 

In a document entitled “Questions for AZ Regional Haze FIP Conference Call” prepared 

by EPA Region IX and dated January 22, 2013 [hereinafter EPA Region IX Q&A], EPA took the 

position that: 

Under the BART Guidelines, combined cycle turbines that are part of a fossil-fuel 

fired steam electric plant more than 250 million Btu/hour heat input are BARTeligible. Thus, based on the information in the SIP, it seems that GT1 is, in fact, 

part of the BART-eligible unit, so its emissions should be included in determining 

compliance. However, additional information from AEPCO and ADEQ may be 

needed to address this question. 

Attachment O, EPA Region IX Q&A, at 8 of 11. In a phone call on January 22, 2013, AEPCO 

committed to working with EPA Region IX and ADEQ to resolve this issue. AEPCO is 

including this issue in the petition for administrative reconsideration to allow that resolution to 

be formalized, if necessary, and to clarify the status of ST1, GT1 and their joint exhaust 

operation, sometimes called CC1. 

AEPCO requests clarification from EPA, and, by copy of this petition, from ADEQ, that 

for purposes of the Regional Haze BART SIP and FIP, emissions from ST1 and GT1 should be 

handled as follows: 

 Emissions from ST1 running in “stand-alone” mode using LNB and existing or upgraded 

FGR capacity (not including GT1 exhaust), must meet the SIP limits. 

 Emissions from ST1 running with GT1, where GT1 emissions are either ducted to the 

windbox (formerly called “combined cycle” mode) or used to provide FGR support, must 

meet the SIP limits. 

 Emissions from GT1 running in “stand-alone” mode (e.g., where emissions are ducted 

through the GT1 stack and not into ST1) are exempt from BART. 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 20 

AEPCO believes that this approach best resolves the problems caused by the dual nature of GT1, 

treating it as part of a combined cycle unit when exhausting through ST1, and hence subject to 

the ST1 BART determination, and treating it as an exempt simple cycle turbine when it is 

operating by itself. Part 51, App. Y, §II.A.3(1) (“Simple cycle turbines are not ‘steam electric 

plants’ because they typically do not make steam.”). GT1 cannot produce steam in its standalone configuration. 

III. EPA Should Reconsider the Averaging Provision 

In its BART FIP, EPA established that compliance is determined for Apache Generating 

Station Units ST2 and ST3 as a 30-day rolling average across both ST2 and ST3, 40 C.F.R. § 

52.145(f)(5)(ii)(A), and for ST1on a 30-day rolling average stand-alone basis, id. § 

52.145(f)(5)(ii)(B). While AEPCO is appreciative of EPA’s responsiveness to the request of 

AUG, which requested an option for averaging, AEPCO believes that the mandatory averaging 

provision inappropriately and unfairly places AEPCO at compliance risk and may also have the 

effect of shortening or limiting maintenance work in a way that is not consistent with good air 

pollution control engineering practice. 

 AEPCO units ST2 and ST3 are used for load following and hence cycle. AEPCO unit 

ST1 is used primarily for peaking. Because these units are subject to fluctuating loads, the 

ability of the units to continuously achieve the stringent NOx limits prescribed, particularly on a 

30-day rolling average basis. Particularly for ST2 and ST3, AEPCO is concerned that one unit 

may trip out and then have a poor restart followed by another trip out, causing the average to 

exceed the limit. This causes several quandaries: (1) restart of the unit is necessary to lower the 

average back into compliance; but (2) restart of the unit will, temporarily at least, exacerbate the 

exceedance. Because the out-of-service unit pounds of NOx are counted against the in-service 

unit, it creates an incentive to hurry maintenance to bring the unit back on-line. This may cause 

additional trips as restart is hurried. AEPCO is not certain that EPA intended this result. 

 AEPCO also believes that it is inequitable to penalize it for taking a unit that is having 

trouble down for maintenance. In such a situation, AEPCO would be doing everything in its 

power to reduce emissions (e.g., it has shut down the unit with excess emissions). Nevertheless, 

AEPCO would, under the rule, continue to accrue penalties until such time as AEPCO was able 

to restart the unit and bring its emissions down (or reduce emissions on the other unit by an 

offsetting amount). AEPCO believes it is inequitable to be penalized for days of violation if the 

sole operating unit is meeting the effective equivalent of the 0.07 lb NOx/MMBtu limit. 

 AEPCO respectfully requests that EPA consider this issue and work with AEPCO and the 

other affected utilities to develop an appropriate response in the FIP. 

IV. Alternative Approaches to Visibility Improvement 

AEPCO understands that the Clean Air Act requires that BART be installed and that 

progress be made toward achieving the national visibility goal in Section 169A of the Act. 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 21 

Nevertheless, Congress wanted this goal to be achieved in a cost-effective way and in a manner 

that does not frustrate the goals of the Rural Electrification Act to provide reasonably priced 

power to the rural areas of the United States, including those rural areas which AEPCO and its 

members serve. 

AEPCO is willing to consider potential alternatives to LNB + OFA + SCR. AEPCO 

believes that alternative approaches could achieve much of EPA’s visibility objectives while 

reducing the costs to AEPCO and its members so that the economic viability of the Apache 

Station is not jeopardized. Such alternative approaches could also provide AEPCO sufficient 

time to plan for the financing and rate impacts. 

Request for Administrative Stay

EPA has authority under the Administrative Procedure Act (“APA”) Section 705, 5 

U.S.C. § 705, and the Clean Air Act (“CAA”) Section 307, 42 U.S.C. § 7607, to grant a stay 

while the rule is being reconsidered. APA Section 705 provides in relevant part that “[w]hen an 

agency finds that justice so requires, it may postpone the effective date of action taken by it, 

pending judicial review.” 5 U.S.C. § 705. The additional showing of “prevent[ing] irreparable 

injury” is a requirement only for a reviewing court, not the agency. Id. CAA Section 

307(d)(7)(b) additionally provides that, “[t]he effectiveness of the rule may be stayed during 

such reconsideration, however, by the Administrator or the court for a period not to exceed three 

months.” 42 U.S.C. § 7607(d)(7)(b). 

EPA’s only precondition for granting a stay is when “justice so requires” under the APA 

and to have commenced reconsideration under CAA Section 307. EPA is not required to review 

a request for stay under the same strict guidelines the statutes impose on the courts, and can grant 

a stay more readily, as the standard under the APA and CAA does not require petitioner to show 

irreparable harm prior to the grant of the stay. 

As explained herein, justice does require EPA to grant a stay and AEPCO will face 

irreparable harm if it is not granted. First, justice requires that EPA stay the rule. The process by 

which EPA promulgated the rule did not take into account information vital to AEPCO, 

including cost and market data that AEPCO, as a small entity, could not develop in time to 

submit during the comment period. These data, presented above, show the substantial and 

ultimately unsustainable impact of the rule on AEPCO. AEPCO also did not know, and could 

not have known, that EPA would consider its Gas Turbine 1 simple-cycle operations would be 

considered part of the BART determination, as this was first stated by EPA in response to 

questions after the rule was finalized. Finally, AEPCO did not have an opportunity to review 

and comment on the promulgated averaging approach in the rule. 

Additionally, a number of parties have already, or will, challenge the rule both 

administratively through petitions for reconsideration and through judicial review in the Ninth 

Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 23 

Patrick Ledger, AEPCO (w/o enclosures) 

 Dwight M. Whitley, Jr., AEPCO (w/o enclosures) 

 Michelle Freeark, AEPCO (w/enclosures) 
Petition for Administrative Reconsideration 

Arizona Electric Power Cooperative, Inc. 

February 2, 2013 

Page 24 

APPENDIX

LIST OF ATTACHMENTS

A. AEPCO Bylaws, Section 7.02 

B. Rate Schedule A and Exhibits and Attachments 

C. Affidavit of Gary E. Pierson, Manager of Financial Services, Arizona Electric Power 

Cooperative, Inc. [Confidential Business Information – Not Supplied] 

D. AEPCO Energy Information Administration (EIA) Form 890 Report 

E. AEPCO Generator Summary Reports, 2004-2011 [Confidential Business Information – 

Not Supplied] 

F. Declaration of Richard E. Stinneford, Managing Member, Washington Utility Group, 

LLC 

G. Affidavit of Richard P. Kurtz, Vice President of Power Services and Planning, Arizona 

Electric Power Cooperative, Inc. [Confidential Business Information – Not Supplied] 

H. Affidavit of Walter T. Bray, Director of Energy Services, Arizona Electric Power 

Cooperative, Inc. [Confidential Business Information – Not Supplied] 

I. Affidavit of Barry A. Brown, Director of Engineer, Arizona Electric Power Cooperative, 

Inc. [Confidential Business Information – Not Supplied] 

J. Affidavit of Peter F. Scott, Chief Financial Officer, Arizona Electric Power Cooperative, 

Inc. 

K. LNB + OFA + SCR Installation Costs and Justification 

L. SO2 Scrubber Upgrade Costs and Justification 

M. Arizona Electric Power Cooperative, Inc., 2013 Financial Forecast, EPA Case with 1.32 

DSC (the “Revised Financial Forecast”) 

N. EPA Clean Air Marketing Division correspondence regarding ST1 

O. EPA Region 9, BART Q&A document 

P. Affidavit of J. Tyler Carlson, Chief Executive Officer, Mohave Electric Cooperative, Inc. 

[Confidential Business Information – Not Supplied] 

Q. Affidavit of Creden W. Huber, Chief Executive Officer, Sulphur Springs Valley Electric 

Cooperative, Inc. [Confidential Business Information – Not Supplied] 

R. Affidavit of Vincent Nitido, Chief Executive Officer/General Manager, Trico Electric 

Cooperative. [Confidential Business Information – Not Supplied]